In the recovery of bitumen or heavy oil from a geological formation or oil reservoir, it is common practice to inject steam or a mixture of steam and hot water. This heats the oil or bitumen and renders it less viscous and less dense, both of which aid in its expulsion from the rock.
In order to generate the steam, a naturally occurring or recycled source water is first treated to convert calcium and magnesium carbonates to sodium bicarbonate. The water is then converted to a mixture of steam and water which typically consists of between 50 and 80 percent by weight of saturated steam and the remainder water at its bubble point, the latter commonly known as the "condensate" phase. Such mixtures are referred to as having steam qualities of between 50 and 80 percent. The mixture of steam and condensate is then either injected into the reservoir or separated into two phases, and only the steam phase injected.
In the steam generator, the bicarbonate ions present in the feedwater thermally decompose as follows: ##STR1##
Much of the carbon dioxide is evolved as a gas and partitions into the vapor phase, while the hydroxyl ion remains in the condensate phase, increasing its pH, often to a value between 9 and 12 when measured at 25.degree. C.
When both the steam and condensate phases are injected into the wellbore, they tend to segregate soon after injection, with the upper part of the formation being contacted by substantially only steam and the lower part by substantially only condensate.
As the steam phase cools in the reservoir, the steam condenses and some of the carbon dioxide present dissolves in the liquid. Thus, the pH of the "condensed steam" phase is lowered as carbonic acid is formed, typically to a value of between 4 and 7 when measured at 25.degree. C. EQU CO.sub.2 +H.sub.2 O.fwdarw.H.sup.+ +HCO.sub.3.sup.-- ( 2a) EQU HCO.sub.3.sup.-- .fwdarw.H.sup.+ +CO.sub.3.sup..dbd. ( 2b)
When the injected fluids contact the formation, the equilibrium between the minerals and the pore fluids is almost invariably destroyed. New minerals may precipitate due to incompatibility between the injected and original waters, some of the original rock matrix may dissolve and be subject to reprecipitation when conditions later are changed in the process of oil recovery, the dissolved minerals may release fine particles which had previously been bound to the rock matrix, the existing minerals may be converted to new minerals through reaction with the injected fluids and with each other, layered clays such as montmorillonite may expand, and fine particles which had previously been weakly held together and to the walls of the rock matrix may deflocculate, or disperse. In some cases, water-in-oil emulsions may be formed or asphaltenes may be precipitated. All of these changes can be harmful to the process of oil recovery.
The obvious method of neutralizing the alkaline condensate phase with a strong acid has the disadvantage that much of the acid will vaporize, causing corrosion and increasing the other problems associated with an acidic steam phase. Consequently, alternative methods have been developed in the prior art to mitigate formation damage caused by alkaline steam condensate. There are few techniques available to deal with formation damage caused by an acidic condensed steam phase.
It is well known in the prior art that the addition of dissolved salts to the injected steam will mitigate clay swelling by maintaining a high ionic content in the condensate phase. However, this method requires a relatively high level of salt, 2 to 4 percent by weight being a typical concentration, which is both costly and can accelerate corrosion.
Hsueh and Reed apply this concept in U.S. Pat. No. 4,802,533 to the condensed steam phase. Ammonium salts are added to the wet steam mixture, whereupon they decompose, and much of the ammonia partitions into the vapor phase. As the steam condenses in the reservoir, the ammonia is absorbed into the condensed steam, thereby increasing its ionic content. This technology is expensive, requiring both a large quantity of ammonium ion and a second chemical additive, a bicarbonate ion source, to prevent the pH of the condensate phase from becoming too low. The pH of the condensed steam phase, containing dissolved ammonia and carbon dioxide (from the bicarbonate), is not controlled.
Day et al, in U.S. Pat. No. 3,384,177, prevent the formation of montmorillonite by a pretreatment which promotes formation of mica and analcite phases. These authors also use ammonia as an additive, but at high concentration and at pH above 11. This technique is not only costly but may also be associated with other harmful reactions taking place between the mineral and fluid phases at high pH, such as silica dissolution.
U.S. Pat. No. 4,475,595 to Watkins et al discloses that ammonium compounds are effective in controlling the dissolution of silica in a reservoir, including "gravel packs" sometimes used to line a wellbore. The only type of formation damage claimed to be controlled in this patent is the dissolution and reprecipitation of silica, no other minerals are claimed to be affected by the practice of this invention.
Nigrini et al extend the prior art in U.S. Pat. No. 4,714,112, disclosing a process for minimizing the dissolution of either silicate of carbonate formations. In this process, ammonium salts are used to maintain the pH of the condensate phase between 8 and 10. Although it is recognized that both the alkaline condensate phase and the acidic condensed steam phase are capable of damage, only the alkaline condensed steam phase pH is directly controlled, and only to within the optimum range for minimizing silica dissolution.
Thus, it would be an improvement over these teachings if a method were available for controlling both the pH of the condensate and condensed steam phases within the ranges optimized for preventing types of formation damage other than those resulting from silica dissolution.
In Watkins et al, U.S. Pat. No. 4,549,609, a method is disclosed for stabilizing swelling clays and reducing fines migration. This U.S. Patent teaches that the addition of an ammonium compound in combination with a precursor comprised of ammonia or a water soluble ammonium ion controls the migration of fines and the swelling of clays in a reservoir.
In U.S. Pat. No. 4,572,296 Watkins et al disclosed that an ammonium compound in combination with a precursor as described above is more effective in controlling silica and gravel pack dissolution than the application of an ammonium compound by itself.
The practice of both the preceding patents focuses on the addition of ammonium compounds, rather than any control of pH. This is evidenced by the need for two separate additives when pH could be controlled by one, and by the choice of preferred additives, which can have the effect of increasing, decreasing, or leaving essentially unchanged the pH of the liquid phase, depending on the additive employed.
Thus, prior art processes employing ammonium compounds to reduce formation damage fall into two general categories: those using pH control to minimize dissolution of rock matrix, and those using control of the ammonium ion concentration to inhibit clay swelling or reduce fines migration. I have found that the techniques of pH control can be applied to the inhibition of clay swelling and the reduction of fines migration, and can also be used to mitigate formation damage caused by formation of water-in-oil emulsions, precipitation of asphaltenes, and formation of clays in situ.
Thus, the objects of this invention are as follows:
1. To provide an improved and more economical method of preventing fines migration in a reservoir through control of the pH of the condensate phase of an injected two phase steam mixture. PA1 2. To provide an improved and more economical method of preventing clay swelling through control of the pH of the condensate phase of an injected two phase steam mixture. PA1 3. To provide a method for minimizing formation of additional clay minerals within a reservoir through control of the pH of either or both of the condensed steam and the condensate phases of an injected single or two phase steam mixture. PA1 4. To provide an improved and more economical method for minimizing the dissolution of carbonate minerals through control of the pH of the condensed steam phase of an injected single or two phase steam mixture. PA1 5. To provide a method for preventing the precipitation of asphaltenes in a reservoir through control of the pH of the condensed steam phase of an injected single or two phase steam mixture. PA1 6. To provide a method for minimizing the formation of water-in-oil emulsions in a reservoir through control of the pH of the condensed steam phase of an injected single or two phase steam mixture.